Geothermal Energy 5 (2017). doi: 10.1186/s40517-017-0081-03
Keywords: Geothermal energy; Geothermal exploration; Outcrop analogue study; Rock proper-ties; Fracture-system parameters; Upper Rhine Graben
Highlights: We test the potential of outcrop studies in exploration for geothermal energy.
Essential reservoir parameters are compared in outcrop and well data.
Because important reservoir parameters strongly differ they are not predictable.
Such studies have limited potential for geothermics in complex faulted areas.
Abstract
Minimizing exploration risk in deep geothermics is of great economic importance. Especially, knowledge about temperature and permeability of the reservoir is essential. We test the potential of an outcrop analogue study to minimize uncertainties in prediction of the rock properties of a fractured reservoir in the Upper Rhine Graben. Our results show that although mineralogical composition, clay content, grain size, and fabric type are basically comparable, porosity and quartz cementation are not.
Young’s Modulus, as observed in the outcrop closest to the reservoir is about twice as high (~64 GPa) as observed in the reservoir (~34 GPa). Most importantly, however, the parameters that describe the fracture system, which are essential to predict reservoir permeability, differ significantly. While the outcrops are dominated by perpendicular fracture sets (striking NE-SW and NW-SE), two different con-jugate fracture sets (striking NW-SE and N-S) occur in the reservoir. Fracture apertures, as reported from the FMI, are one order of magnitude wider than in the outcrop. We conclude that our outcrop analogue study fails to predict important properties of the reservoir (such as permeability and poros-ity). This must be in part because of the tectonically complex setting of the reservoir. We propose that analogue studies are important, but they must be treated with care when attempting to predict the controlling parameters of a fractured reservoir.
3 This Chapter is largely identical to the article entitled „Bauer, J.F., Krumbholz, M., Meier, S., Tanner, D.C., 2017.
Predictability of properties of a fractured geothermal reservoir: The opportunities and limitations of an outcrop analogue study. Geothermal Energy 5 (1), 24.”
6.1 Background
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Background
The most essential requirements for a geothermal reservoir are sufficient temperature and permea-bility (e.g., Jung et al., 2002; Paschen et al., 2003; Schulz et al., 2009; Schulz, 2011). Whereas the geo-thermal gradient for a given region is commonly constrained to a sufficient degree, estimates of po-rosities, fracture systems, permeabilities, and therefore the achievable convective heat flow in a planned fractured reservoir are subject to large uncertainties (Domenico and Palciauskas, 1973;
Agemar et al., 2012). Permeability provided by barren fractures, commonly referred to as structural permeability (e.g., Sibson, 1996; Jolie et al., 2015), and thus the convective heat flow, may be substan-tially increased in fault-related reservoirs by locally enhanced fracture intensities and therefore create prime targets for geothermal exploration (Paschen et al., 2003; Jung, 2007; Vidal et al., 2016). How-ever, estimating the potential of a fractured hydrogeothermal reservoir is a major problem. This is because of the limited amount of data available to estimate the permeability in the subsurface and thus to predict achievable flow rates for geothermal power exploitation (at least 20 kg s-1 MW-1, Franco and Villani, 2009). Permeability values are typically at best restricted to a small number of existing wells close to the envisaged reservoir and not necessarily representative of larger volumes. It is thus inherent that the quality of predictions made on reservoir properties largely depends not only on the distance between exploration wells in the reservoir, but also on the heterogeneity of the latter (e.g., Müller et al., 2010; Fitch et al., 2015). This holds particularly true for fluvial sedimentary rock sequences that are characterized by frequent changes of rock properties, both laterally and vertically (Morad et al., 2010). This is the case for the Lower Triassic (Buntsandstein) in the Upper Rhine Graben (URG), where lithostratigraphic correlations are further complicated by a complex system of fault block tectonics (Boigk and Schöneich, 1970; Sauer et al., 1982; Villemin et al., 1986).
Predictions of heterogeneities on a larger scale from point information such as borehole logs have therefore large uncertainties. Geophysical methods, such as 2D or 3D reflection seismics, in contrast, provide continuous spatial information, which can be used to image large structural geological heter-ogeneities, such as faults. Due to their resolution, however, they can only provide limited data on small-scale structures such as fractures.
One common approach to reduce the observational gap between well and seismic data is to include outcrop data into the exploration strategy (Chesnaux et al., 2009; Philipp et al., 2010; Howell et al., 2014; Reinecker et al., 2015). The advantages of this approach are that, if good outcrops exist, lateral as well as vertical heterogeneities of rock- and fracture-system properties can be observed in detail.
These properties are challenging or even impossible to sample adequately using borehole logs and in general they are invisible to seismics.
An outcrop will always be different from its subsurface analogue, even if it exposes age-equivalent rocks, since it must have experienced a different burial/uplift history and thus different diagenetic conditions. In addition, outcrops are not always available in the desired size, quality, and/or quantity.
Consequently, the resolution of the different methods used to analyse a reservoir needs to be scaled accordingly. For instance, the scale of observation is important with respect to fracture orientation.
While (sub)recent microcrack orientations are commonly consistent over large volumes (e.g., Vollbrecht et al., 1994; Krumbholz et al., 2014a) and therefore predictable, larger fractures have usu-ally a more complex history and thus exhibit more variable systematics. A direct implication is that the strength of the rocks is also scale dependent (Krumbholz et al., 2014b).
However, outcrop studies only provide limited 2D/3D information and it is necessary for the observed rock properties to be corrected to be comparable with the conditions at reservoir depth. In addition,
71 the deformation history of the target formation may be different from that of the outcrop. For in-stance, faults at depth may juxtapose rock units, but possibly not in the outcrop.
The structural permeability provided by fractures (joints and faults) may vary locally within several orders of magnitude. Numerous studies have shown that the fracture intensity in a fault zone often increases towards the fault core, and with increasing fault displacement (e.g., Hull, 1988; Faulkner et al., 2011; Reyer et al., 2012; Shipton et al., 2013). Thus, damage zones of large-scale fault zones are prime targets for geothermal exploration. When evaluating fault properties, it is, however, crucial to take into account that (1) faults and fault zones may act either as conduits, barriers, or as combined conduit-barrier systems for fluid flow (e.g., Chester and Logan, 1986; Caine et al., 1996; Evans et al., 1997; Farrell et al., 2014) and (2) that the characteristics of faults and brittle fault zones can vary con-siderably, even on small spatial scale (e.g., Caine et al., 1996; Schulz and Evans, 2000; Faulkner et al., 2010; Laubach et al., 2014). Consequently, reliable prediction of the structural inventory of faults and its hydrological impact on the planned geothermal reservoir is crucial. Given the amount of parameters needed to be investigated to predict the properties of fractured and fault-related reservoirs, careful selection of outcrop analogues is essential to ensure their comparability to the reservoir under explo-ration.
This study focusses on the rock properties and fracture-system parameters in outcrops and compares them with equivalent reservoir data. The study was carried out in the Lower Triassic of the Upper Rhine Graben (URG), a potential, but still underexplored target for geothermal exploitation. Outcrop data are compared with reservoir information from the geothermal well Brühl GT1 within the URG, close to the eastern graben shoulder. In total, four outcrops on the eastern and western graben shoulders were selected; they belong to the Lower to Middle Buntsandstein (Fig. 6.1).
Figure 6.1: a) Location of the URG b) Solid geological map of the study area. The locations of the outcrops studied (LS: Leistadt;
CL: Cleebourg; RS: Riesenstein; KF: Kammerforster) are indicated by red dots, the geothermal well Brühl GT1 is represented by a blue diamond (map modified after Eisbacher and Fielitz, 2010). c) Permo-Carboniferous troughs and highs in the URG.
Black lines indicate Variscan fault traces (after Schumacher, 2002). d) Fault map showing major fault traces in the graben and on adjacent graben shoulders that indicates the complex deformation history (modified after Meixner et al., 2016). Red lines in b) to d) show main Cenozoic boundary faults of the URG.
We analyse the rock parameters that directly control the reservoir performance, they are porosity, and fracture-system parameters, such as mineralization, orientation, intensity, and aperture. Other rock parameters, such as tensile strength, Young’s Modulus, and uniaxial compressive strength are of interest from an engineering point of view, e.g. in terms of borehole stability or in case reservoir stim-ulation becomes necessary.
6.2 Site descriptions and methods
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Site descriptions and methods
Regional geology and geothermal setting
The URG is part of the European Cenozoic Rift System and strikes NNE-SSW, its length is about 300 km, and it is about 30 – 40 km wide (e.g., Illies, 1977; Ziegler, 1992; Schumacher, 2002; Fig. 6.1).
The structural pre-rift setting of the URG was established during the Variscan Orogeny; Permo-Car-boniferous wrench tectonics formed NE- to ENE-trending fault zones (e.g., Ziegler, 1990; Schumacher, 2002; Schwarz and Henk, 2005). These fault zones form the boundaries of the Variscan Internides and Permo-Carboniferous troughs and highs (Fig. 6.1c). Early Carboniferous, NNE- to SSW-oriented, sinis-tral shear zones are associated with Lower Carboniferous to Permian intrusive bodies (Vosges, Black Forest, Odenwald; e.g., Ziegler, 1990; Schumacher, 2002; Schwarz and Henk, 2005).
The formation of the URG in the Cenozoic occurred in two main phases and was controlled by multi-phase reactivation of Variscan and Permo-Carboniferous discontinuities (e.g., Illies, 1972; Schumacher, 2002; Ziegler et al., 2006). The first rifting phase occurred during the Late Eocene until Late Oligocene, and was characterized by NW-SE- to WNW-ESE-directed extension (e.g., Ziegler, 1992; Schwarz and Henk, 2005; Ziegler and Dèzes, 2006). The second main phase of graben formation began in Early Mi-ocene and was marked by reorientation of the stress field to NE-SW extension. As a consequence, the major graben-forming faults are characterized by sinistral and dextral oblique displacements, local in-version, and normal displacements (Illies and Greiner, 1979; Schumacher, 2002). Uplift and erosion was limited to the central and southern parts of the URG, while subsidence and sedimentation shifted southwards during the Miocene (Bartz, 1974; Pflug, 1982). The recent maximum horizontal stress com-ponent in the URG is NW-SE to NNW-SSE-oriented (Heidbach et al., 2008). However, fault-plane solu-tions reveal a change in faulting regime from dominantly strike-slip faulting in the southern part to a combination of strike-slip- and extensional movement in the northern URG (Larroque et al., 1987;
Plenefisch and Bonjer, 1997).
The Buntsandstein rocks that were studied here represent the marginal facies of the Germanic Basin and comprise mainly fluvial to playa deposits. The Odenwald-Spessart High separates different depo-sitional areas of the studied outcrops (Fig. 6.1c). Within the Palatinate Forest, fluvial and aeolian facies alternate, whereas aeolian sediments are absent in the Odenwald (Hagdorn and Nitsch, 2009). Since the unconformities that define the basic lithostratigraphic units of the Buntsandstein in the northern Germanic Basin are not clearly documented in the study area, distinction between the different units is difficult (Dachroth, 1985; Bourquin et al., 2006; Szurlies, 2007; Feist-Burkhardt et al., 2008; Hagdorn and Nitsch, 2009). Further complications are introduced by the varying Buntsandstein thicknesses;
they vary from about 60 m in the south of the graben to approximately 500 m around Karlsruhe, but further northward the thickness decreases again to about 300 m (Boigk and Schöneich, 1970; Stober and Bucher, 2014). Additionally, the Buntsandstein can be found at different depths, ranging from about 1000 m below the land surface, down to 4000 m near Karlsruhe. This is due to intense block tectonics and differences in the subsidence and exhumation history (Boigk and Schöneich, 1970; Sauer et al., 1982; Villemin et al., 1986). One consequence of the complex geology is that several lithostrati-graphic classifications of the Buntsandstein units exist (e.g., Backhaus, 1974; Richter-Bernburg, 1974;
Hagdorn and Nitsch, 2009). Within the URG, the regional geothermal gradient is elevated to 45 – 50°C km-1, with local hot spots that have temperature gradients of up to 100°C km-1 and make the URG a prime target for geothermal exploration in Germany (Schellschmidt and Clauser, 1996;
Stober and Bucher, 2014). This positive temperature anomaly is commonly explained by a raised Moho
73 due to the graben formation (Brun et al., 1992) or by advective fluid flow (Schellschmidt and Clauser, 1996; Pribnow and Schellschmidt, 2000).
Study area
The graben shoulders expose Triassic rocks of Lower to Upper Buntsandstein. The outcrops studied (Figs. 6.1 and 6.2) comprise one outcrop with a fault zone (Fig. 6.2a; Cleebourg) and one without an exposed fault zone (Fig. 6.2b; Leistadt) on the western graben shoulder. On the eastern graben shoul-der, two additional outcrops without fault zone exposure were studied (Fig. 6.2c; Riesenstein and Kam-merforster).
The location of the geothermal well Brühl GT1 is southwest of Heidelberg, approximately 12 km west of the eastern graben shoulder (Fig. 6.1a, d). The thickness of the reservoir is 162 m and lies between 3157 and 3319 m measured depth (MD), close to a system of three NNW-, W-, and NE-dipping transtensional faults that are part of a negative flower structure (Lotz, 2014a). The targeted reservoir zone is intersected by an 80° westwards-dipping transtensional fault. The normal vertical displacement of this fault is approximately 70 m (Reinecker et al., 2015), although the strike-slip component is un-known.
Figure 6.2: Geological maps of the outcrops studied on the western graben shoulder, a) Cleebourg and b) Leistadt, and on the eastern graben shoulder, c) Riesenstein and Kammerforster (maps modified after Eisbacher and Fielitz, 2010).
Methods Outcrop-based methods
In this study, we used classic structural geological fieldwork, including mechanical rock-property measurements, and optical microscopy, which included image analysis of selected thin sections of rock samples.
Standard parameters of the fracture system were recorded using scanline and window-sampling methods (e.g., Terzaghi, 1965; Priest, 1993; Adler et al., 2013). The recorded fracture-system parame-ter include orientation, intensity (number of fractures per meparame-ter), connectivity, aperture, and whether the fractures are cemented or not.
Laboratory-based methods:
16 rock samples were taken: 12 from the outcrop at Cleebourg, 1 from Leistadt, 2 from Riesenstein, and 1 from Kammerforster. From each of the samples, at least six right-circular cylinders were taken for mechanical testing. The rocks were classified according to their fabric type after Miall (1978) and dried samples were used to determine the ultrasonic shear-wave velocity (TB), uniaxial compressive strength (=>?), static Young’s Modulus (A), tensile strength (CD), and bulk density (]•). Transient times of shear-wave velocities were measured at a frequency of 0.25 MHz. The compression tests were car-ried out according to ISRM 1989 (Fairhurst and Hudson, 1989) and the indirect tensile strength was
6.2 Site descriptions and methods
74
measured using a Brazilian test after ISRM 1981 (Brown, 1981). The bulk densities of the samples were calculated using their mass to volume ratios.
For comparison of petrophysical and petrographical properties, 24 thin sections of the samples from Cleebourg were saturated with blue resin. Using optical microscopy, we determined porosity, cemen-tation, grain size, and mineralogical composition. For petrographical quantification of the rock, thin sections were analysed using classical point-counting (300 points) and classified after McBride (1963).
Petrographic analyses of rock samples of the other outcrops (Leistadt, Riesenstein, and Kammerfor-ster) were previously performed by Soyk (2015).
Porosity and grain size were assessed by digital image analysis with the software ImageJ (Rasband, 2011). An optical scan of each thin section with a resolution of 300 dpi was taken under plane polarized light. To distinguish between the grains and the dyed resin-filled pore space, a binary image was cal-culated, with white pixels representing the grains and black pixels the pore space. The porosity was then calculated as an area fraction in ImageJ. The sizes of about 100 grains along a scanline were meas-ured and classified after Wentworth (1922). While our 2D approach cannot compete with the accuracy of 3D analysis, e.g., Sahagian and Proussevitch (1998), Berg et al. (2016) concluded that, in the majority of cases, the accuracy of 2D porosity estimates can be considered sufficiently close to 3D results.
Analytical methods:
To estimate the matrix permeability (žg) in the reservoir from the properties determined in the out-crop study, the porosity-permeability relation (Kozeny-Carman, Eq. 6.1) was utilized,
žg9 Ÿ €G Z1 r €@8 ’¡qD8
180“ [m²], Eq. 6.1
in which € is the porosity and ¡qD is the mean grain size (Freeze and Cherry, 1979).
To estimate the structural permeability in analytical models, it is an accepted approach to approxi-mate naturally rough fractures by parallel plates with a constant aperture and to apply the cubic law (e.g., Snow, 1965, 1969; Witherspoon et al., 1980; Bear, 1993). Consequently, the permeability (ž‚) of sets of differently-oriented fractures was estimated using:
ž‚9 1
The reservoir formation was analysed based on drill cuttings, i.e. no core was taken, but pumping and injection tests and standard wireline logging were carried out.
The geophysical logging devices that were used are listed in Table 6.1. The logs are available for the uppermost 140 m of the reservoir section.
The density-correction log from the LDS tool records the absolute deviation from the measured bulk density. For deviations larger than 15 [kg m-3], the determined bulk density was found to be not reliable and corresponding well sections were rejected during the evaluation of the bulk density and, thus, also for calculations of bulk porosity and the dynamic elastic parameters. The logging quality was further evaluated by the well caliper from the FMI tool. In the places where the well caliper returned values that deviate more than 15% from the bit size (> 0.22 m, < 0.16 m), log signals from the LDS were found to affect the bulk density measurements and therefore rejected in further interpretation.
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Table 6.1: Wireline-logging tools used in this study (GR: Gamma Ray, FMI: Formation Micro Imager, DSI: Dipole Sonic Imager, LDS: Litho Density Sonde. MD: Measured Depth).
tool log interval (MD) (m) measurements of evaluation of
GR 3305 – 3150 natural gamma rays sand/clay content, depth correlation of the various logging tools
FMI 3295 – 3150 electrical resistance, well cali-per
sedimentary facies, detection of open/closed fractures, fracture orienta-tion, fracture intensity, fracture apertures DSI 3293 – 3150 compressional- and shear-wave
velocities
The sonic- or matrix porosity Фg was estimated with the Wyllie time-average method using p-wave velocities (Schlumberger, 1989). This method requires an estimate of fluid and matrix travel times (∆†‚ef`W = 607 sec m-1, ∆†g§bi`¨= 182 sec m-1) and compares these with travel times measured in the reservoir (∆†eda):
Фg9 ∆†edar ∆†g§bi`¨
∆†‚ef`W r ∆†g§bi`¨ [-]. Eq. 6.4
Since sonic log-derived porosities largely ignore secondary porosity, such as fractures, and the density log responds primarily to as the bulk porosity, the difference was used to calculate the fracture poros-ity, referred to the secondary porosity index (SPI) of the reservoir (Schlumberger, 1989).
To compare the bulk densities of the dried surface samples and the fluid saturated rocks in the well, the log measurements were corrected by replacing the water-filled pores with air.
Elastic properties of the reservoir rock include dynamic Young’s Modulus (Ad). It is derived from the measured densities and elastic wave velocities (compressional- TU and shear-wave velocity TB):
AW9 ]TB8∙3TU8r 4TB8
TU8r TB8 [Pa]. Eq. 6.5
The formation structural permeability was determined equivalent to outcrop calculations, using the cubic law (Eq. 6.2). Data on fracture apertures and densities are based on FMI images; data on fracture mineralization was analysed using a combination of FMI, LDS, and DSI, provided by J. Reinecker (GeoT).
The results were compared with determined bulk permeabilities from pumping and injection tests.
The reservoir transmissivity is specified as follows:
C 92.3 ∙ ~ fluid viscosity (Kruseman and Ridder, 1992).
6.3 Outcrop properties
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Outcrop properties
Rock properties
Whereas the Triassic sandstones in outcrops on the western graben shoulder are yellowish, brownish to red coloured, and, in some cases, they are totally bleached, the investigated sandstones from the eastern flank are red, and not, or only slightly, bleached. Typical fabric types of the studied rock sam-ples comprise trough bedding, partly with mudstone intraclasts (St) and low-angle (<10°) cross-bedding (Sl). Both fabric types are interbedded by thin silty claystone layers.
Despite different lithostratigraphies, the mineralogical compositions for all studied outcrops cluster narrowly in the fields of subarkose and lithic subarkose;
the Leistadt samples show an increased amount of lithic components (Fig. 6.3).
Rock porosity estimations based on image analysis show that the rock porosities at the eastern flank have only minor variations and lie between 3 and
Rock porosity estimations based on image analysis show that the rock porosities at the eastern flank have only minor variations and lie between 3 and